During drilling operations, drilling fluid, also referred to as drilling mud, is pumped at high pressure down the well bore. Mud pumps draw drilling fluid from mud tanks and pump the drilling fluid at high pressure down the drill string. The drilling fluid jets out of the drill bit and cleans the bottom of the hole. The drilling fluid moves back up the well bore in the space between the drill sting and the side of the well bore, known as the annulus, flushing cuttings and debris to the surface. The pressurized drilling fluid creates down-hole hydrostatic pressure which promotes the prevention of formation fluids from entering into the well bore during drilling operations and suspends cuttings in the well bore during interruptions to drilling.
The mixture of drilling fluid, formation fluids and debris travelling back up the well bore to the surface is referred to as the ‘well bore returns’ or ‘drilling returns’. The well bore returns also frequently contain dissolved gas which moves from the formation surrounding the well bore being drilled into the drilling fluid in the annulus.
Upon arrival at the surface, a series of valves and pipes are utilized to controllably direct the well bore returns to a mud gas separator, or to a de-gasser. A separator typically comprises a cylindrical or spherical vessel and can be either horizontal or vertical. It is used to separate gas from the drilling fluid. In the separator, the drilling fluid containing gas is usually passed over a series of baffles designed to separate gas and mud. Liberated free gas is moved to a flare line while the mud is discharged to a shale shaker and to a mud tank.
A de-gasser is used when the gas content of the drilling fluid is relatively lower and it operates on much the same principles as the separator. A vacuum is applied to the drilling fluid as it is passed over baffles to increase surface area thereby promoting the liberation of dissolved gas.
During drilling operations, it is extremely important to maintain constant down-hole hydrostatic pressure to try and prevent formation fluids and gases from entering into the well bore as mentioned above. This can be challenging due to shifting well bore conditions and frequent interruptions to drilling operations, such as tripping pipe. To maintain down-hole hydrostatic pressure, conventional drilling operations typically utilize one or more chokes at the well head. The primary role of the choke is to regulate the flow of well bore returns from the well head. The choke comprises an orifice that can be selectively opened or closed to control the flow rate of the well bore returns. Controlling the flow of the well bore returns at the well head in turn regulates down-hole pressure. There are both fixed and adjustable chokes, the latter being more conducive to enabling the fluid flow and pressure parameters to be adjusted to suit process and production requirements. However, there are problems associated with restricting the cross-sectional area of a conventional choke orifice to passively regulate down-hole pressure. First, as the cross-sectional area of the choke decreases, the likelihood of the choke becoming clogged with cuttings and debris increases. Second, for a given volumetric flow rate, as the cross-sectional area of the choke decreases, the velocity of the well bore returns within the choke increases, which increases the scouring effects of solids in the well bore returns on the choke. Third, the chokes do not accurately measure well bore return volume.
What is needed is an apparatus and a method of controlling well bore returns to regulate down-hole hydrostatic pressure that mitigates the problems of existing choke devices.